Separable completion architecture

ABSTRACT

A technique facilitates performance of a work over on a completion used in a wellbore. The completion comprises an upper completion coupled with a lower completion by a mandrel and a latch. When a work over is to be performed, the upper completion is separated by moving a cutter device down along the mandrel and operating the cutting device to sever the mandrel. Once the mandrel has been severed, the latch may be activated to release the upper completion for removal.

CROSS-REFERENCE TO RELATED APPLICATION

The present document is based on and claims priority to U.S. Provisional Application Ser. No.: 61/649,610, filed May 21, 2012, incorporated herein by reference.

BACKGROUND

Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, referred to as reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. In a variety of downhole applications, completions are deployed downhole to facilitate many types of well related operations. In some applications, a lower completion and an upper completion are both deployed downhole into a wellbore. When the upper completion is in need of service or updating, a work over is sometimes performed by pulling the entire completion or by separately pulling the upper completion. If the upper completion is separately pulled, the upper and lower completions are connected by, for example, a latch having a shear pin. The shear pin may be sheared via tubing or annulus pressure by utilizing a seal between the tubing and the annulus. However, the shear pin style latch is susceptible to inadvertent activation under high loading and/or seal failure in certain environments, e.g. subsea well environments.

SUMMARY

In general, a system and methodology are provided for performing a work over on a completion. The completion comprises an upper completion coupled with a lower completion by a mandrel and a latch. When a work over is to be performed, the upper completion is separated by moving a cutting device down along the mandrel and operating the cutting device to sever the mandrel. Once the mandrel has been severed, the latch may be activated to release the upper completion for removal.

However, many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:

FIG. 1 is a schematic illustration of a completion system having an upper completion coupled with a lower completion in a wellbore, according to an embodiment of the disclosure;

FIG. 2 is an enlarged schematic illustration of the completion with the upper completion and the lower completion coupled by a latch and a mandrel, according to an embodiment of the disclosure;

FIG. 3 is a schematic illustration similar to that of FIG. 2 but in a different operational state, according to an embodiment of the disclosure;

FIG. 4 is a schematic illustration similar to that of FIG. 3 but in a different operational state, according to an embodiment of the disclosure;

FIG. 5 is a schematic illustration similar to that of FIG. 4 but further illustrating a cutting device used to facilitate separation of the upper completion from the lower completion, according to an embodiment of the disclosure;

FIG. 6 is a schematic illustration similar to that of FIG. 5 but in a different operational state, according to an embodiment of the disclosure;

FIG. 7 is a schematic illustration similar to that of FIG. 6 but in a different operational state, according to an embodiment of the disclosure;

FIG. 8 is a schematic illustration of the completion after removal of the upper completion, according to an embodiment of the disclosure;

FIG. 9 is a schematic illustration of the completion after another upper completion with a contraction joint has been run downhole for engagement with the lower completion, according to an embodiment of the disclosure;

FIG. 10 is an illustration of the contraction joint, illustrated in FIG. 9, in an extended position, according to an embodiment of the disclosure;

FIG. 11 is an illustration of the contraction joint, illustrated in FIG. 9, in a partially collapsed position, according to an embodiment of the disclosure;

FIG. 12 is a schematic illustration of another example of the completion, according to an embodiment of the disclosure;

FIG. 13 is a schematic illustration similar to that of FIG. 12 but showing a cutting device moved down along an interior of the mandrel, according to an embodiment of the disclosure;

FIG. 14 is a schematic illustration similar to that of FIG. 13 but in a different operational state in which the mandrel has been severed, according to an embodiment of the disclosure;

FIG. 15 is a schematic illustration similar to that of FIG. 14 but in a different operational state, according to an embodiment of the disclosure;

FIG. 16 is a schematic illustration of the completion illustrated in FIG. 12 after removal of the upper completion, according to an embodiment of the disclosure; and

FIG. 17 is a schematic illustration of the completion after another upper completion with contraction joint has been moved down hole into engagement with the lower completion, according to an embodiment of the disclosure.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of some embodiments of the present disclosure. However, it will be understood by those of ordinary skill in the art that the system and/or methodology may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

The disclosure herein generally involves a system and methodology related to utilizing a downhole completion system. By way of example, the system and methodology may be used to facilitate servicing, e.g. a work over, of a downhole completion system. The completion system comprises an upper completion and a lower completion in which the upper completion is coupled to the lower completion by a latch and a mandrel. Additionally, communication line segments, e.g. hydraulic control line segments and electric control line segments of the upper and lower completions, may be releasably engaged by at least one wet connect, e.g. an electro-hydraulic wet connect. By employing the mandrel, the completion structure is able to withstand high axial loading. Release of the upper completion can be achieved by cutting the mandrel transversely with a cutting device to enable release of the latch.

The latch and the mandrel enable the upper and lower completions to be deployed downhole into a wellbore in a single trip. According to an embodiment of the disclosure, the latch may comprise male and female portions which are joined and behave as one piece until the latch is activated. Activation of the latch enables the upper completion to be disconnected from the lower completion and pulled out of the wellbore for a work over.

To release the latch, the mandrel is transversely cut, e.g. circumferentially cut, with a suitable cutter run into the well. Examples of a suitable cutting device comprise an explosive cutter, a chemical cutter, or a mechanical cutter. The cutting device is run downhole into the wellbore via a conveyance, such as wireline, coiled tubing, slick line, pipe, or another suitable conveyance. In some embodiments, the cutting device is run downhole along an interior of the mandrel. For example, the mandrel may comprise a pipe with a hollow interior having sufficient size to enable conveyance of the cutting device down to a desired cut-through region.

Referring generally to FIG. 1, an embodiment of a completion system 30 is illustrated as comprising an upper completion 32 coupled with a lower completion 34. The completion 30 is deployed in a wellbore 36 which extends through a zone or a plurality of zones 38 within a surrounding formation/reservoir 40. In this embodiment, the upper completion 32 is coupled to the lower completion 34 in a manner which supports high axial loading. For example, the upper completion 32 is coupled to the lower completion 34 by a coupling system 41 in the form of a mandrel 42 and a latch 44. The mandrel 42 may be formed of a continuous material uninterrupted by separable joints to provide a strong, solid mandrel for supporting axial loading. By way of example, mandrel 42 may comprise a continuous pipe or tubing having a hollow interior 46.

Depending on the specific application, completion system 30 may comprise a variety of components designed to facilitate different types of well operations, including well production operations, well treatment operations, and other well related operations. In the example illustrated in FIG. 1, many types of components are illustrated although the type, number and arrangement of components may vary substantially from one application to another. By way of example, completion 30 comprises a plurality of communication lines, e.g. control lines, such as at least one hydraulic communication line 48 and at least one electric communication line 50. The communication lines 48, 50 may be selectively connected and disconnected via at least one wet connect. In the illustrated example, the communication lines 48, 50 may be connected and disconnected by a hydro-electric wet connect 52. A sealing, contraction joint 54 also may be employed to facilitate connection and/or disconnection of upper and lower completions.

The completion system 30 also may comprise a casing 56 and various upper completion components, such as a surface controlled subsurface safety valve 58 and a gas lift mandrel 60. Additionally, the lower completion 34 may comprise a plurality of packers 62 position to isolate well zones 38 along wellbore 36. In some applications, the lower completion 34 also may comprise at least one flow control valve 64 and a variety of sensors and/or gauges 66. By way of further example, the lower completion 34 may comprise a chemical injection mandrel 68 supplied by chemical injection lines 70. Flow control valve 64 may be actuated by hydraulic fluid supplied through corresponding hydraulic control lines 48. Additionally, the lower completion may comprise a mechanical sliding sleeve 72 or other valve system used for stimulation. Many of these components may be deployed in each well zone between sequential packers 62 to control flow with respect to the associated well zone 38.

Referring generally to FIG. 2, an enlarged illustration is provided of a portion of completion 30 which shows the upper completion 32 joined to the lower completion 34 for movement downhole into wellbore 36 in a single trip. In this example, the upper completion 32 is joined with the lower completion 34 by latch 44 and mandrel 42 which is in the form of tubing having hollow interior 46. The mandrel 42 also has a cut-through region 76 which provides a location for severing the mandrel 42 in a transverse direction to effectively separate the mandrel 42 into pieces which enable retrieval of the upper completion 32. However, prior to separation and retrieval of upper completion 32, the solid, integral mandrel 42 enables substantial axial loading to be placed on completion system 30 during deployment and operation.

As illustrated in FIG. 2, the embodiment of completion 30 comprises packer or packers 62 which have not yet been actuated against the surrounding casing 56. Additionally, the hydro-electric wet connect 52 comprises a receptacle housing 78 and a stinger 80 received in the hydro-electric wet connect receptacle housing 78 against a stop 82. The hydro-electric wet connect 52 also comprises a plurality of communication line coupling features 84 to facilitate coupling and decoupling of communication lines 48, 50. By way of example, hydraulic and electric communication lines 48, 50 may be combined in a cable 86, such as a flat pack cable. Additionally, the cable 86 may be wrapped in a coil 88, e.g. a flat pack coil, within contraction joint 54.

In the embodiment illustrated, latch 44 is a collet-style latch and comprises a latch collet 90 having collet fingers 92 which are placed in compression and received in a latch profile 94. A latch collet support 96 securely holds collet fingers 92 in latch profile 94 until the latch 44 is actuated for release of the upper completion 32. A stop housing 98 and associated stop 100 may be employed to facilitate movement when activating latch 44 and to provide support for withdrawal of the upper completion 32.

The mandrel 42 and latch 44 securely combine the upper completion 32 and lower completion 34 for conveyance downhole into wellbore 36 with packers 62 in the contracted position illustrated in FIG. 2. Once the completion 30 is delivered to a desired location along wellbore 36, e.g. once the completion 30 is on depth, the packer or packers 62 are set, as illustrated in FIG. 3. The packers 62 may be set by, for example, applying tubing pressure down through mandrel 42 and against a temporary plug 101.

Once packers 62 are set, a desired well operation may be initiated. For example, a well injection operation, such as a well treatment, may be initiated by pumping fluid into the desired well zones 38. The well operation also may comprise producing fluids from the well zones 38. As illustrated in FIG. 4, well fluids, e.g. gas and/or oil, may be produced up through mandrel 42 as indicated by arrow 102. In the specific example, mandrel 42 is in the form of tubing, such as production tubing extending upwardly to a surface location.

If a work over of upper completion 32 is desired due to development of a downhole problem or for another suitable reason, separation of the upper completion 32 from the lower completion 34 is initiated. As illustrated in FIG. 5, a cutter device 104 is deployed down into wellbore 36 via a conveyance 106. Conveyance 106 may comprise, for example, coiled tubing, wireline, slick line, pipe, or another suitable conveyance. Similarly, cutting device 104 may be in the form of a variety of cutting devices, including explosive cutters, chemical cutters, mechanical cutters, or other suitable cutters. The cutting device 104 comprises a cutting mechanism 108 which may be designed to form a transverse cut 110 through mandrel 42. By way of example, cutting mechanism 108 may comprise explosives, chemicals, mechanical blades, or another suitable cutting mechanism for cutting through mandrel 42 by forming transverse cut 110. In the illustrated example, cutting device 104 is deployed down through hollow interior 46 of mandrel 42 and the cut 110 is formed in a generally radial direction from an interior of the mandrel 42.

After forming transverse cut 110, the mandrel 42 is separated into pieces which allows the upper completion 32 to be lifted or picked up by, for example, the upper portion of production tubing forming mandrel 42 (as illustrated in FIG. 6). When the upper completion 32 is picked up, the pieces of mandrel 42 separate and latch collet support 96 is moved to allow the collet fingers 92 to flex inwardly. Continued lifting flexes the collet fingers 92 and releases the latch collet 90 from latch profile 94, as illustrated in FIG. 7. The transverse cutting of mandrel 42 and the activation of latch 44 by lifting upper completion 32 enables release and removal of the upper completion 32 for a work over or other desired activity, as illustrated in FIG. 8.

When the work over is completed and/or when a different upper completion 32 is prepared, the upper completion 32 is again lowered down into wellbore 36 for engagement with lower completion 34, as illustrated in FIG. 9. In this example, the upper completion 32 comprises a version of contraction joint 54 mounted on tubing 112, e.g. the production tubing discussed above. In some embodiments, mandrel 42 is formed from a portion of the production tubing 112 extending down into engagement with the lower completion 34. Depending on the application, the new or reworked upper completion 32 may be run downhole with a simplified latch 44 having latch collet 90 again designed for engagement with latch profile 94. The contraction joint 54 also may be a simplified contraction joint which is shown in a partially stroked position in FIG. 9.

Referring generally to FIGS. 10 and 11, an example of a simplified version of contraction joint 54 is illustrated. In this embodiment, contraction joint 54 is coupled with production tubing 112 and comprises a stroke region 114 which provides space for contraction. Other features may comprise a protection cover 116 surrounding the coil 88 along with an anti-rotation pin 118 and a slot 120 for the anti-rotation pin 118. A shear member 122, such as a shear pin also may be employed to prevent contraction of the joint until a sufficient axial, contraction force acts on the contraction joint 54 to cause contraction, as illustrated in FIG. 11.

The simplified contraction joint 54 also may comprise a seal stack 124 which seals against an internal, slidable tube/mandrel 126 having a stop 128 which is movably captured within stroke region 114. Other features of contraction joint 54 may comprise a slot (or slots) for receiving the cable/flat pack 86. A clamp 132 may be used to secure the cable 86 in slot 130. In the example illustrated, a segment of production tubing 112 also extends below the contraction joint 54 and into latch 44.

Referring generally to FIG. 12, another embodiment of completion 30 is illustrated. In this embodiment, many of the components are the same or similar to those described above with respect to the previous embodiment and those same or similar components have been labeled with the same reference numerals. In this latter example, the latch 44 has been changed so that collet fingers 92 act in tension. As illustrated, the collet fingers 92 engage latch profile 94 which has been positioned internally of the collet fingers 92. Additionally, latch collet support 96 is positioned externally of the collet fingers 92 and serves to securely hold collet fingers 92 in the radially inward position engaging latch profile 94.

Similar to the previously described embodiment, release of the upper completion 32 and separation of latch 44 initially involves movement of cutting device 104 downhole, as illustrated in FIG. 13. In the example illustrated, cutting device 104 is deployed down through hollow interior 46 of mandrel 42 and the cut 110 is formed in a generally radial direction from an interior of the mandrel 42 via the cutting mechanism 108. The cut 110 may again be formed transversely to separate mandrel 42 into upper and lower pieces.

After forming transverse cut 110, the pieces of mandrel 42 are separated, when the upper completion 32 is lifted or picked up by, for example, production tubing 112, as illustrated in FIG. 14. As with the previous embodiment, the cable coil 88 can expand, as further illustrated in FIG. 14. As the upper completion 32 is picked up and the pieces of mandrel 42 separate, the latch collet support 96 is again moved to allow the collet fingers 92 to flex. However, in this embodiment, the collet fingers 92 flex outwardly. Continued lifting flexes the collet fingers 92 and releases the latch collet 90 from latch profile 94, as illustrated in FIG. 15. The transverse cutting of mandrel 42 and the activation of latch 44 by lifting upper completion 32 enables release and removal of the upper completion 32 for a work over or other desired activity, as illustrated in FIG. 16. It should be noted that in the embodiments described herein, the hydro-electric wet connect 52 may be used to enable selective disengagement and re-engagement of the hydraulic control lines 48 and/or electric lines 50.

When the work over is completed and/or when a different upper completion 32 is prepared, the reworked or new upper completion 32 is again lowered down into wellbore 36 for engagement with lower completion 34, as illustrated in FIG. 17. In this example, the upper completion 32 again comprises the simplified contraction joint 54 mounted on tubing 112, such as the production tubing discussed above. Depending on the application, the upper completion 32 may be run downhole with a simplified latch 44 having the latch collet 90 designed for engagement with latch profile 94.

As described herein, the completion system may be used in a variety of applications, including numerous well production and treatment applications. Depending on the specifics of a given tool system, well application, and environment, the design of the overall completion system 30, upper completion 32, lower completion 34, mandrel 42, latch 44, wet connect 52, contraction joint 54, and other components may vary. Additionally, the completion system may be designed for use in many types of wells, including vertical wells and deviated, e.g. horizontal, wells. The wells may be drilled in many types of formations with single or multiple production zones. Additionally, a variety of cutting devices may be used to sever the mandrel from an internal position and/or an external position. The specific cutting mechanism also may be designed in a variety of forms or combinations of forms.

Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims. 

What is claimed is:
 1. A method for utilizing a downhole completion system, comprising: coupling an upper completion with a lower completion via a latch and a mandrel; deploying the upper completion and the lower completion downhole into a wellbore in a single trip; and separating the upper completion from the lower completion by cutting transversely through the mandrel and releasing the latch.
 2. The method as recited in claim 1, wherein separating comprises cutting through the mandrel with an explosive.
 3. The method as recited in claim 1, wherein separating comprises cutting through the mandrel with a chemical cutter.
 4. The method as recited in claim 1, wherein separating comprises cutting through the mandrel with a mechanical cutter.
 5. The method as recited in claim 1, wherein coupling comprises coupling with the latch via a collet having collet fingers held radially outward into engagement with a latch profile.
 6. The method as recited in claim 1, wherein coupling comprises coupling with the latch via a collet having collet fingers held radially inward into engagement with a latch profile.
 7. The method as recited in claim 1, wherein separating comprises lifting the upper completion to release the latch after cutting transversely through the mandrel.
 8. The method as recited in claim 1, wherein coupling comprises coupling via the mandrel in the form of a tubing.
 9. The method as recited in claim 1, further comprising coupling a plurality of control lines with a hydro-electric wet connect.
 10. The method as recited in claim 9, wherein separating comprises separating the hydro-electric wet connect and the plurality of control lines.
 11. A method for performing a work over on a completion, comprising: moving a cutter device down along an interior of a tubing coupling an upper completion with a lower completion in a wellbore; operating the cutter device within the tubing to sever the tubing; and removing the upper completion from the wellbore.
 12. The method as recited in claim 11, further comprising lifting the upper completion after severing the tubing to release a latch.
 13. The method as recited in claim 11, further comprising lifting the upper completion after severing the tubing to release a collet of a latch.
 14. The method as recited in claim 12, further comprising separating communication lines at a wet connect.
 15. The method as recited in claim 12, further comprising separating electric and hydraulic communication lines at a hydro-electric wet connect.
 16. The method as recited in claim 11, wherein moving comprises moving an explosive cutter device.
 17. The method as recited in claim 11, wherein moving comprises moving a mechanical cutter device.
 18. A system, comprising: a lower completion; an upper completion; and a coupling system coupling the upper completion to the lower completion, the coupling system having a latch and a mandrel with a cut-through region, the latch and the mandrel cooperating such that cutting the mandrel at the cut-through region severs the mandrel into a plurality of pieces and enables release of the latch.
 19. The system as recited in claim 18, further comprising a hydro-electric wet connect releasably coupling a plurality of control lines extending from the upper completion to the lower completion.
 20. The system as recited in claim 18, further comprising a cutter device deployed along an interior of the mandrel. 